Caprock breach determination technique

ABSTRACT

A technique for determination of out of zone injection. The technique may include taking temperature readings of the well at locations adjacent the cap rock during injection of injection fluid into the injection well at temperatures that are below that of the cap rock. Analysis of the rate of change in temperatures adjacent the cap rock may be used to monitoring effects of the injection application including deciphering cap rock breach of injection fluid when the rate of change substantial enough.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Provisional Application Ser. No. 62/189,006, which was filed on Jul. 6, 2015, and is incorporated herein by reference in its entirety.

BACKGROUND

Field

The present disclosure relates to techniques for completing a reservoir. More particularly, the present disclosure relates to tools and methods for intelligent completions and monitoring systems.

Description of the Related Art

Exploring, drilling, and completing hydrocarbon wells are generally complicated, time consuming, and ultimately very expensive endeavors. Thus, maximizing recovery is a significant concern in any well operation. Along these lines, over the years, wells have tended to become deeper and deeper, perhaps exceeding 30,000 feet in depth, and of fairly sophisticated architecture to help ensure greater access to the reservoir. Similarly, increased attention has also been paid to monitoring and maintaining the health of such wells. A premium is also placed on maximizing the total recovery as well as the recovery rate.

In terms of maximizing the total recovery and rate of recovery, a variety of enhanced production techniques may be employed beyond a well's uniquely tailored, reservoir-focused architecture. For example, across a given oilfield, there may be several wells. Of course, many may be production wells with a focus on recovering hydrocarbons from the reservoir. However, others may be injection wells that do not “produce”. Instead, as originally suggested by Joh F. CarlI in the late 1800's, injection wells may be focused on injecting a fluid into the reservoir so as to enhance production at the other producing wells.

As with any well, the injection wells are drilled through cap rock and various formation layers at the oilfield in order to reach the targeted reservoir. However, instead of recovering fluids from the reservoir, the injection wells are used to deliver injection fluid, generally water, into the reservoir so as to maintain or drive up pressure in the reservoir. So, for example, as a production well in one location of the oilfield begins to recover hydrocarbons from the reservoir, an injection well in another location of the oilfield forcibly injects water into the reservoir. In this manner, pressure in the reservoir is maintained even as the production well continues to remove fluid production. In fact, to further enhance recovery, the injection well may not only maintain pressure, but actually increase pressure in the reservoir beyond that initially present. This is often referred to as an “artificial” manner of enhancing recovery. Indeed, this technique of enhancing recovery generally increases the total recovery and total rate of recovery from the reservoir.

Unfortunately, adding pressure to the reservoir as described above may involve a delicate balance that is often a challenge to tightly maintain. For example, in circumstances where injection wells unintentionally overpressure the reservoir, the cap rock which isolates the underlying reservoir may be prone to becoming damaged. On the other hand, too little pressure in the reservoir may also damage the cap rock in circumstances where the depleting reservoir is no longer able to support the cap rock. In either circumstance, a damaged cap rock may have significantly adverse effects on the recovery efforts undertaken by the production wells.

Damage to the cap rock in the form of cracking means that water injected into the reservoir by injection wells is able to migrate beyond the intended reservoir target or “out of zone”. This is often referred to as “out of zone injection” or OOZI. At a minimum, injection fluids that migrate out of zone are unable to help enhance recovery efforts in the manner detailed above. Worse, however, is the possibility that the cracked cap rock may damage the reservoir, for example, upon collapse of the cap rock. In fact, this may even result in total loss of control over reservoir control. That is, the migration of injection fluids across the damaged cap rock may be indicative of the catastrophic circumstance of cap rock inability to adequately retain other fluids as well, such as the targeted reservoir fluids. Thus, production from the entire oilfield may be at risk.

In order to help avoid such catastrophic circumstances, efforts exist to monitor for the first signs of OOZI. As with most other potentially hazardous issues, the earlier the detection, the more likely it is that damage may be kept to a minimum. For example, the volume of fluid injected into the reservoir may be closely monitored and correlated to the amount of pressure that is maintained in the reservoir. Thus, in theory, if sufficient pressure is not maintained in the reservoir, compared to the volume of fluid injected, this will be an indication that the fluid may have migrated out of zone. Unfortunately, there is a significant time lag between the time of injection and the corresponding reservoir pressure. Indeed, it may take months before OOZI is actually detected in this manner. By this time, the opportunity to prevent significant, if not catastrophic, damage to the cap rock may no longer be available. Furthermore, even if detected in time, where several injection wells are utilized, the specific location of the injection well and corresponding cap rock damage may remain unknown.

As a practical matter, operators generally account for the strength of the cap rock and attempt to maintain reservoir pressure at a certain percentage pressure below the cap rock tolerance. For example, if the cap rock strength indicates a maximum pressure tolerance of about 20,000 PSI, an effort to utilize injection wells without exceeding about 15,000 PSI may be undertaken. Of course, this means that the full degree of potential injection pressure is not utilized. By the same token, this also does nothing to help provide an indication of OOZI should it still occur. Instead, operators are still left largely reliant on the delayed volume versus pressure technique detailed above to alert of OOZI issues that may have been ongoing for months.

SUMMARY

A method of determining out of zone injection at an injection well is provided. The method includes positioning an array of sensors adjacent cap rock which defines a portion of the well. Thus, an initial temperature correlated to the cap rock may be recorded. During operations, fluid may be injected into the well at a temperature different than the initial temperature. Therefore, the sensor array may be monitored for resultant temperature correlations indicative of out of zone injection of the fluid into the cap rock.

In some embodiments, a system is disclosed for detecting breach of cap rock with injection fluid at an injection well at an oilfield. The system includes a vertically disposed sensor device in the injection well adjacent the cap rock and a control unit with a processor in communication with the sensor device to monitor temperature during injection of the injection fluid for an anomalous rate of change indicative of cap rock breach.

However, many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features can be understood in detail, a more particular description may be had by reference to embodiments, some of which are illustrated in the appended drawings, wherein like reference numerals denote like elements. It is to be noted, however, that the appended drawings illustrate various embodiments and are therefore not to be considered limiting of its scope, and may admit to other equally effective embodiments.

FIG. 1 is an overview of an oilfield accommodating a production well and an injection well equipped with a cap rock breach detection sensor array therein.

FIG. 2 is an enlarged view of a portion of the injection well taken from 2-2 of FIG. 1 including a portion of the sensor array.

FIG. 3A is an enlarged view of the portion of the injection well taken from 3-3 of FIG. 2 highlighting the sensor array adjacent the cap rock.

FIG. 3B is a top cross-sectional view of the injection well at a location encompassing the sensor array and adjacent cap rock.

FIG. 4 is a chart depicting detected sensor array temperatures in the region of the cap rock over time with a perceptible point of out of zone injection indicated.

FIG. 5 is a flow-chart summarizing an embodiment of utilizing a sensor array to monitor a cap rock of an injection well for out of zone injection thereinto.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure. However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

In the specification and appended claims: the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element”. Further, the terms “couple”, “coupling”, “coupled”, “coupled together”, and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements”. As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the disclosure.

Additionally, the embodiments detailed herein are directed at detecting out of zone injection or OOZI from an injection well and through cap rock at an oilfield. Specifically, as used herein the term, “cap rock” is meant to refer to any substantially non-porous formation or formation layer over a reservoir that, in absence of a well or other intentional access, discourages migration of therefrom. The term is also meant to include cement, well casing, and other well structure/material adjacently sealed against the cap rock which, like the cap rock itself, does not provide a leak path so long as the integrity thereof is maintained. Cracks and flaws in such material structure that reflect a reduction in integrity may also be referred to as OOZI if such cracks or flaws allow reservoir or injection fluid to migrate from below the cap-rock.

Embodiments are described with reference to certain techniques for determination of OOZI related to compromised integrity. In particular, the techniques involve monitoring well temperatures over time for changes that may be the result of cap rock that is breached by injection fluids. For example, the injection fluid may be notably cooler than the cap rock, in which case the injected fluid will rapidly cool the rock through which it passes through a process of advection. That chilled rock will cool nearby regions through thermal conduction, even without fluid movement through those regions. The injected fluid will also chill the tubing through which it is passing from the surface to the reservoir and that chilled tubing will cool the cap-rock through conduction. Thus, sensors in the well adjacent the cap rock will detect a temperature change from heat flux may detect a temperature drop at an accelerated rate, indicative of cap rock breach by the injection fluid. Of course, other valuable information may be obtained regarding the cap rock with such a temperature array in place. Regardless, so long as the capability exists to detect temperature changes indicative of cap rock breach by injection fluid, appreciable benefit may be realized.

As clear to those skilled in the art, in the case that a fluid is injected which is warmer than the cap rock then a similar phenomenon will take place where again there will be an anticipated temperature change that can be taken as a base temperature change and then a variation of that change that is indicative of breach of fluid. For exemplification purposes, we shall use the term “cooling” but the invention is equally applicable in the case that the injected fluid is warmer than the rock (e.g. in steam-assisted-gravity-drainage wells) and also covers the case when the injection fluid has a cyclical or varying temperature.

Referring specifically now to FIG. 1, an overview of an oilfield 101 is shown accommodating a production well 160 and an injection well 180. Each well 160, 180 traverses various formation layers in the form of a surface layer 197, cap rock 195, and a reservoir containing production layer 190. However, while the production well 160 is directed at collecting production fluid 145 from the reservoir, the injection well 180 is directed at introducing an injection fluid 140 to the reservoir as an aid to the uptake of the production fluid 145 by the production well 160.

As indicated above, each of the wells 160, 180 breaches a layer of cap rock 195 in reaching the production layer 190. Thus, the integrity of each well 160, 180 is largely reliant upon maintaining sufficient integrity of the cap rock 195. In the case that the wells are cemented then successful integrity of the cap rock 195 includes integrity of the cement. For example, in circumstances where the cap rock 195 adjacent the injection well 180 is substantially cracked or degraded by the pressure of the injection fluid 140, uptake of production 145 may be compromised. That is, not only might the effectiveness of the injection well 180 be limited, but fluids may begin to migrate beyond the cap rock 195 and outside of the reach of the production well 160. These injection fluids might create unwanted overpressure of certain zones or even the breach of fluid to a seabed. Of course, a variety of other circumstances may lead to the possibility of damaged cap rock 195. Regardless, in the embodiment shown, the injection well 180 is equipped with a breach detection sensor device in the form of an array 100 therein. Therefore, as detailed further below, operators may be provided with an early form of cap rock breach or “out of zone injection” (OOZI) pointing to potential issues with the cap rock 195 at the injection well 180.

Continuing with reference to FIG. 1, injection well equipment 150 includes a rig 155 over a well head 157 that receives injection fluid 140, generally water, from an injection line 152. The well 180 is defined by casing 185, and runs through to the production formation layer 190 where the casing 185 and layer 190 is cemented and then intentionally pierced by perforations 142. In this way, the injection fluid 140 may be pumped downhole through injection tubing 189 to the perforations 142 at a pressure sufficient to raise the pressure in the reservoir of the production layer 190.

The production well 160 is of similar architecture with cemented casing and then perforations 147 penetrating the production layer 190 and casing 165. However, in this case, the well 160 is configured for the uptake of production fluids 145 from the region. More specifically, the production well equipment 175 includes a rig 177 over a well head 179 with a production line 176 for carrying away of the production fluids 145. Furthermore, with the aid of the injection well 180, the added pressure in the region may increase this rate of production as well as the total production attained from the production layer 190. Additionally, with the sensor array 100 at the injection well 160 and analysis of data therefrom performed at a control unit 125, the increased rate and total production may take place without undue risk of unintentional damage to the cap rock 195.

Referring now to FIG. 2, an enlarged view of a portion of the injection well 180 taken from 2-2 of FIG. 1 is shown. In this view, a portion of the sensor array 100 is shown secured to the casing 185 at a location immediately adjacent the cap rock layer 195. Further, the sensor array 100 is shown with different individual sensors 201, 202 at different vertical locations. Thus, temperatures may be detected at different vertical locations of the well 180, immediately adjacent the cap rock 195. As detailed further below, this temperature information may be correlated to provide information about the condition of the cap rock 195 itself over time including the possibility of breach (e.g. OOZI).

The depicted sensors 201, 202 may be of a variety of different types suitable for downhole use. This may include platinum resistance temperature thermometers, fiber-optic temperature sensing and heat-flux sensors. The fiber-optic sensing may be interferometric, e.g., relying on Raman backscatter or built as discrete arrays, e.g., Fiber-Bragg gratings. In the case of heat-flux sensors, thin-film varieties may be utilized which may or may not be assembled directly on the tubing or casing. Of course, the architectural disposition of the array 100 may also be of different configurations. For example, instead of being located at the interior of the casing 185, the array 100 may be located at the outside of the casing 185, more directly adjacent the cap rock 195 (with perhaps only a cement layer therebetween). In this latter case then inductive coupling may be used to communicate from tubing to exterior to casing. Further, in another embodiment, the sensor device may be a fiber optic line utilized as a distributed temperature change sensor as opposed to utilizing discrete individual sensors of an array 100. Regardless, so long as temperature-related information is obtained from known locations adjacent the cap rock 195, techniques as detailed herein may be employed to ascertain a condition of the cap rock 195. Specifically, with comparatively cold injection fluid 140 flowing through the injection tubing 189 and ultimately into the production layer 190, through the perforations 142, is there a change in the rate of temperature drop or heat-flux in the cap rock 195 sufficient to ascertain OOZI?

Referring now to FIG. 3A, an enlarged view of the portion of the injection well 180 taken from 3-3 of FIG. 2 is shown. In this view, the sensor array 100 adjacent the cap rock 195 is further highlighted with each discrete sensor 201, 202 at a known location. Furthermore, in this view it is apparent that the cap rock 195 is cracked in different locations 300. Thus, a degree of OOZI with injection fluids 140 migrating from the intended production layer 190 and across the cap rock 195 is apparent. Whether this is due to excessive pressure brought about by the injection fluid 140 itself, a byproduct of initial completions operations, or for some other reason, the potential harm to the recovery application remains. Thus, as detailed below, the OOZI information provided by the sensor array 100 and analyzed by the control unit 125 of FIG. 1 may be invaluable.

With brief added reference to FIG. 3B, a top cross-sectional view of the injection well 180 of FIG. 3A is shown at a location encompassing the sensor array 100 and adjacent cap rock 195. In this view, another perspective of damaged or cracked areas 300 of the cap rock 195 is apparent as is the array 100 and its location adjacent the now damaged and potentially permeable cap rock 300.

While a variety of different protocols may be called for in injection well applications, generally, the injection fluid delivered through the injection tubing 189 and into the production layer 190 will be at a temperature that is well below that of the surrounding formation layers, including the cap rock 195. Thus, even in the absence of any damage 300, the cap rock 195 might be expected to slowly cool as the underlying production layer 190 is initially cooled by the injection fluid 140. By way of example, depending on the size and layout of the formation layers, an injection fluid of 50° F. injected at a rate of 15,000 barrels per day might be expected to cool cap rock 195 that is initially at 120° F. by about 0.1° F./meter every 100 days or so even in absence of any cracking 300. However, in circumstances where the cap rock 195 has become cracked 300 or otherwise permeable and susceptible to migrating OOZI, the rate of temperature change might look quite different.

Referring now to FIG. 4, with added reference to FIGS. 3A and 3B, a chart is shown depicting detected sensor array temperatures in the region of the cap rock 195 over time. Because the sensor array 100 is positioned at the interior of the casing 185, the actual temperatures detected are closer to that of the injection fluid 140 (e.g. 50°-51° F.) than the cap rock 195. However, it is the rate of change in the temperature over time or heat-flux to/from the rock that is monitored to determine the condition of the cap rock 195. For example, in embodiments where the array 100 is positioned outside of the casing 185, the temperatures would normally be at higher levels (e.g. 115° F.-125° F.), yet it would still be the change in rate over time that would be indicative of cap rock condition.

Recalling that the cap rock 195 of FIGS. 3A and 3B has become cracked 300, the chart of FIG. 4 reveals the emergence of this cracking based on the change in the rate of temperature drop as detected by the array 100. Specifically, when looking at four different discrete sensor readings of the array 100, a relatively uniform, non-anomalous decrease in temperature is apparent for about 100 days (see 450). This decrease will typically be exponential in nature, i.e. the rate of cooling will slowly decrease over time, where the rate of cooling is proportional to the temperature difference driving that cooling. We refer to such a rate of cooling as “steady” or “non-anomalous” Over this period of time, whether an individual sensor is located very near the bottom of the cap rock 195 (e.g. 201) or further up (e.g. 202), a steady decline in temperature is apparent as temperatures move from near 50.6° F. down closer to 50.5° F. Again, this does not appear to be atypical given that the array 100 in the embodiment at hand is in greater proximity to the injection fluid 140 which may be at about 50° F., itself). That is, for the first 100 days, the decline in detected temperature is steady and attributable to the slowly decreasing temperature of the adjacent cap rock 195 due the underlying injection of this colder water into the formation 190 below in combination with the cooling of the cap rock due to the chilled tubing. The rate of decay may be correlated against standard exponential formulations well known in the industry or may be compared to the result of a computational modelling package. Such modelling packages may be routinely updated and adjusted based on additional data as temperature change information is collected and utilized at various cap rock formation types over time.

However, as also depicted in the chart of FIG. 4, the rate of decrease in temperature detected by the array 100 drops sharply in an anomalous fashion after about 100 days. Further, the rate of the drop is more dramatic for sensors such as 201 that are closer to the bottom of the cap rock 195 (see 401). It is at this point in time that the rate of temperature drop has substantially changed as detected by each sensor of the array 100. For example, as the cracking 300 into the cap rock 195 emerges as shown in FIG. 3A, the lowermost sensor 201 will detect the initial rate drop in temperature (see 401). This stands to reason given that, as the injection fluid 140 begins to traverse or migrate across the cap rock 195, it first encounters areas adjacent this lowermost sensor 201 having its first effects there.

In the embodiment shown after about 100 days, it is apparent that the cracking 300 into the cap rock 195 has emerged, effecting the sensors 201, 202 (and others) in succession, starting from the one (201) closest to the bottom of the cap rock 195. The information provided by the chart of FIG. 4 is informative in a variety of ways. For example, not only is the emergence of OOZI apparent shortly after its occurrence, but the manner of progression of the OOZI fluid temperature is also apparent. For example, the uppermost sensor of the array 100 that is furthest from the bottom of the cap rock 195, reflected by 404, does not experience nearly as dramatic of a rate change as 201 (e.g. 401) or 202 (e.g. 402). This reflects an OOZI whose fluid is warming as it moves from cracks at the bottom of the cap rock 195 and migrates upward. The rate at which the fluid warms up the fracture is indicative of its flow rate within that fracture. By the same token, it is also apparent that it is not the case of a sudden collapse of the cap rock 195 with a rush of OOZI almost immediately traversing the entirety of the cap rock 195. Instead, the successive movement upward, reflected by the greater temperature rate changes at the lowermost sensor detections is reflected.

Perhaps more importantly, the information provided by the temperature array technique is available to the operator in ready fashion. That is, as opposed to waiting months to find out that cracking has occurred, the operator may be alerted of the situation in the near term. In the specific example, of the chart of FIG. 4, it is clear in looking at readings over less than 5 days (from day 100 to day 105), that a breach or OOZI has occurred. Thus, corrective action may be taken within a matter of days of the OOZI, generally under about 10 days, as opposed to months after the fact.

Continuing with added reference to FIG. 1, the control unit 125 may be equipped with a processor for analyzing the temperature information such as that of FIG. 4. Further, pre-stored parameters in the processor may be utilized to direct a host of different types of corrective action once the analysis confirms OOZI. For example, a temperature/time gradient threshold may be established for each sensor of the array in advance of injection based on advance sampling and modeling. Once the threshold for any sensor is breached, the control unit 125 may be utilized to direct particular forms of corrective action. Similarly, in addition to detection by detection or sensor by sensor thresholds, an average threshold for the entire array may be utilized as well as an average for each sensor based on several detections by that sensor. Additionally, the injection well may be temporarily shut-off and warmback readings collected and analyzed to confirm breach. In this way premature corrective action may be avoided.

Referring now to FIG. 5, a flow-chart is shown summarizing an embodiment of utilizing a sensor array to monitor a cap rock for out of zone injection OOZI. As shown, operations are initiated with the injection fluid being pumped through the injection well and into the reservoir at the production layer (see 520). In the embodiment shown, the well is then shut in and warmback recorded as discussed above and indicated at 530. In this way, a record of the thermal conductivity of the well in absence of cracking or other issues may be established and pre-stored. This may be helpful in establishing thresholds, ascertaining expected rate of temperature changes in absence of cracking, etc. as described hereinabove.

Injection may resume as indicated at 540 with the array utilized to monitor temperatures over time (see 550). As long as there is no indication of threshold breach, injection may resume as indicated at 560. However, a breach may be detected as noted at 570. This may be significant as shown at 400 of FIG. 4 and warrant immediate corrective action. In the embodiment shown, however, a preliminary shut-in for additional recordation of warmback may take place to contrast against the initial warmback at 530 (see 580). In this confirmation of threshold breach may take place in advance of the corrective action noted at 590. For example, the corrective action may include dramatically reducing the injection rate (e.g. from 15,000 barrels per day down to 10,000) or even shutting off the injection well for sake of safeguarding the cap rock. Thus, to ensure that the corrective action is truly warranted, the preliminary step of shutting in the well and running another warm back may be advantageous.

Embodiments described hereinabove include techniques for detecting out of zone injection or OOZI through a cap rock adjacent a well in a practical, early stage manner. That is, in contrast to correlating injection volume and pressure over an extended period of months, temperature information from readings adjacent the cap rock may be analyzed in real-time. Thus, a reliable earlier stage indication of OOZI may be provided to allow evasive measures in advance of any catastrophic damage to the underlying reservoir. Once more, in situations where several injection wells are utilized simultaneously, direct monitoring of each injection well may provide added information in terms of the location of potential cap rock issues.

Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses, such as are within the scope of the appended claims. 

1. A method of determining out of zone injection of a fluid from an injection well and into cap rock over a reservoir at an oilfield, the method comprising: positioning a sensor device in the injection well adjacent the cap rock; recording an initial temperature of the sensor device corresponding to the cap rock; injecting the fluid into the injection well at a temperature different from that of the cap rock; monitoring the sensor device for a change in temperature at an anomalous rate corresponding to out of zone injection of the fluid into the cap rock.
 2. The method of claim 1, further comprising: taking corrective action when the out of zone injection of the fluid into the cap rock is detected during the monitoring of the sensor device.
 3. The method of claim 2, wherein the corrective action comprises one of reducing a rate of the injecting of the fluid into the injection well and shutting off the injection well.
 4. The method of claim 2, further comprising: shutting in the injection well; and monitoring temperature of the sensor device during the shutting in of the injection well for a warmback period to confirm the reduction in temperature at a rate corresponding to the out of zone injection in advance of the taking of the corrective action.
 5. The method of claim 1, further comprising: shutting in the injection well; and storing temperature of the sensor device during the shutting in of the injection well for a warmback period to establish reference temperature data.
 6. The method of claim 1, wherein the injecting of the fluid into the injection well raises a pressure in the reservoir, the method further comprising recovering production fluids from the reservoir through a production well at the oilfield.
 7. The method of claim 1, wherein a rate of reduction in temperature is greater at the lowermost location of the sensor device.
 8. The method of claim 1, wherein the rate of reduction in temperature is detected in less than about 10 days of the emergence of the out of zone injection into the cap rock.
 9. A system for detecting breach of cap rock with injection fluid at an injection well at an oilfield, the system comprising: a vertically disposed sensor device in the injection well adjacent the cap rock; a control unit with a processor in communication with the sensor device to monitor temperature during injection of the injection fluid for an anomalous rate of change indicative of cap rock breach.
 10. The system of claim 9, wherein the sensor device is selected from a group consisting of an array of discrete sensors and a fiber optic distributed temperature change sensor.
 11. The system of claim 9, wherein at least one of the discrete sensors is selected from a group consisting of a resistance temperature thermometer, fiber Bragg temperature sensor, and a heat-flux sensor.
 12. The system of claim 9, wherein the sensor device is mounted to one of an interior of casing defining the well at the location of the cap rock and an exterior of the casing defining the well at the location of the cap rock. 